IR 05000334/1985027

Insp Rept 50-334/85-27 on 851201-31.No Violation Noted.Major Areas Inspected:Licensee Actions on Previous Insp Findings, Plant Operations,Housekeeping,Fire Protection,Physical Security ESF Verification & Maint Activities

ML20140D000
Person / Time
Site:	Beaver Valley
Issue date:	01/16/1986
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20140C982	List: IR 05000334/1985027 ML20140C977
References
50-334-85-27, IEB-79-24, IEB-81-03, IEB-81-3, IEG-79-24, NUDOCS 8601290051
Download: ML20140D000 (15)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /85-27 Docket N Licensee: Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279 Facility Name: Beaver Valley Power Station, Unit 1 Location: Shippingport, Pennsylvania Dates: December 1 - 31, 1985 Inspectors: W. M. Troskoski, Senior Resident Inspector A. A. Asars, Resident Inspector Approved by: 1 %

. E. Tripp, hief, Reactor Projects Section 3A Date Inspection Summary: Inspection No. 50-334/85-27 on December 1 - 31, 198 Areas Inspected: Routine inspections by the resident inspectors (71 hours8.217593e-4 days <br />0.0197 hours <br />1.173942e-4 weeks <br />2.70155e-5 months <br />) of licensee actions on previous inspection findings, plant operations, housekeeping, fire protection, LSA shipments, radiological controls, physical security, engi-neered safety features verification, maintenance activities, surveillance activi-ties, reactor protection system items, and cold weather preparation Results: Several reactor protection system deficiencies were reviewed concerning the testing of the overtemperature delta temperature channels and the setpoint of the negative flux rate trip (Section 8).

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TABLE OF CONTENTS Page Persons Contacted.................................................... 1 Plant Status............................................ ............ 1 Followup on Outstanding Items...... ................................. 1 Plant Operations............................................. ....... 4 General....................... .............................. .. 4 Operations...................................................... 5 Plant Security / Physical Protection........... .................. 7 Radiation Controls............ ....... ...................... 7 Plant Housekeeping and Fire Protection.......................... 7 Engineered Safety Features (ESF) Verification... .................... 7 Surveillance Activities......................... .................... 7 Reactor Plant Component Cooling Water System.......... .............. 9 (CCR) Maintenance Activities Reactor Protection System Items...................................... 10 Over Temperature - Delta T Surveillance Testing................. 10 Negative Flux Rate Trip Setpoints............................... 11 Cold Weather Preparation............................................. 12 1 Exit Interview....................................................... 13

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DETAILS Persons Contacted J. J. Carey, Vice President, Nuclear Group R. J. Druga, Manager, Technical Services

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T. D. Jones, General Manager, Nuclear Operations W. S. Lacey, Plant Manager J. D. Sieber, General Manager, Nuclear Services N. R. Tonet, General Manager, Nuclear Engr. & Constr. Unit The inspector also contacted other licensee employees and contractors during this inspectio Plant Status

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The plant operated at full power throughout the inspection period.

't Followup on Outstanding Items The NRC Outstanding Items (0I) List was reviewed with cognizant licensee per-sonnel. Items selected by the inspector were subsequently reviewed through discussions with licensee personnel, documentation reviews and field inspec-tion to determine whether licensee actions specified in the OI's had been satisfactorily completed. The overall status of previously identified in-spection findings was reviewed, and planned and completed licensee actions

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were discussed for those items reported below:

(Closed) Unresolved Item (84-24-01): Check process monitor response at low gamma energy level Previously, the licensee used only high energy sources (Cobalt 60 and Cesitm 137) for calibration of monitors RM-VS-101B and RM-LW-104. The manufacturer's technical manual recommended that a Barium (Ba-133)

source be used to validate the primary calibration curve at the low energy region. The licensee subsequently updated MSP 43.13, Rad Process Monitor RM-VS-101B Ventilation Gas - Calibration, and MSP 43.18, Rad Process Monitor RM-LW-104 Liquid Waste Effluent - Calibration, to include the low energy sourc About 20 other MSPs still need to be updated prior to their next scheduled

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use. Inspector discussions with the procedures group indicated that appro-

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priate steps were taken to prohibit the use of these procedures until the appropriate revisions are complete. The inspector had no further concerns and this item is close (Closed) Unresolved Item (84-24-02): Check plateau curve for process monitor ,

detectors. It was noted that MSP 43.13 did not require a plateau check to <

abtain the operating high voltage setting. Discussions with the licensee in- '

dicated that they do not perform primary calibrations with gas and liquids containing all of the isotopes of interest at the station because of the

! technical difficulties involved. Rather, the rad monitor vendor, Victoreen, maintains t primary calibrated detector for both gas and solid sources (Co-balt, Barium, etc.) to obtain the original detector efficiency curv The

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licensee sends their solid sources to Victoreen, who, in turn, performs a secondary check to obtain the high voltage range for transfer of calibration data. Additional steps to perform a plateau check for these monitors are therefore, not require A second concern noted that MSP 43.13 and 43.18 did not require the low energy discriminator setting to be determined. The inspector reviewed the latest revision to these procedures and verified that appropriate changes were mad The remaining MSPs are currently flagged to require these changes prior to their issuance for the next scheduled performance. This item is close (Closed) Unresolved Item (85-02-05): Determine why the condensate pump recirc valve RK series instrument rack print did not reflect actual as-built plant conditions. This item was last reviewed in Inspection Report 334/85-06 and left open pending review of corrective actions recommended by the Technical Advisory Group. It was determined that the cause of the problem was due to:

(1) an oversight by personnel performing the field work, and (2) a lack of management control over the design change and modification process for the non-safety related turbine plant that resulted in out-of-date prints (RK series). The licensee has updated the drawing and in the future, the Con-struction Group will use plant loop calibration procedures rather than generic calibration procedures. The loop calibration procedures are specific for each instrument and contain as-built drawings. In addition, the licensee has in-structed Construction Startup Group personnel to isolate and clear any device which may be activated during calibration, regardless of whether it is in service or not. This item is close (0 pen) Unresolved Item (85-11-01): This item concerns six (6) fire dampers located in the Cable Spreading Room (CS-1). These dampers initially had a 1.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> fire rating but were upgraded to a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> rating during the first refueling outage in 1980. When the dampers were placed back into operation, the carbon dioxide lines to the damper blow out release mechanism were inad-vertently left cappe The licensee noted that conditions such as those de-scribed in IE Notice 83-41, Activation of Fire Suppression System Causing Inoperability of Safety Related Equipment, might require leaving some of the dampers disconnected from the blowout feature. During the licensee's evalu-ation of this issue, American Nuclear Insurers (ANI) issued a letter, dated September 9, 1985, addressing their concerns with the fire dampers. The let-ter stated that in 1975 a full discharge test was conducted in CS-1 with the affected six dampers arranged to trip on CO2 discharge. Based on the results of this test, ANI continues to recommend reinstallation of the trip mechanism for all six dampers. As a result of this recommendation, the licensee issued ECN 589 to revise release linkage arrangements on the six affected fire dam-pers. The licensee has completed the installation of all six release mechan-isms. The post modification C02 puff test has not yet been performed; this item will remain open pending positive puff testing of the damper (Closed) Inspector Follow Item (85-13-03): Followup to determine the status of the wind speed and direction strip chart recorders and the availability of this dat Currently, the licensee utilizes two methods of monitoring the

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wind speed and direction, a strip chart recorder and computer output. The strip chart recorders are an old model and replacement paper is difficult to obtain. In the interim period, the licensee is using paper with a different

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scale than the recorder, but there is a correct scale on the top of the re-corder. The inspector compared the readings from both the strip chart recor-der and the computer and verified that they were the same. Human factors deficiencies of this type have been independently identified by the control room design review for Beaver Valley, Unit 1. Resolution of these individual deficiencies are being tracked by the licensee. This item is considered close (Closed) Inspector Follow Item (85-15-02): Confirm that the licensee has positive control at all times over the dosimetry issue booth. Previously, the inspector had found the TLD booth left unattended and unlocked during backshifts after the licensee implemented changes to the shift rad technician assignments. The licensee stated that the booth would be secured when unat-tended in the future. Through subsequent discussions with speral rad tech-nicians, the inspectors verified that they were knowledgeable of this require-ment. Backshift tours found the booth locked at all times. This item is closed.

, (0 pen) Inspector Follow Item (85-16-03): Followup on licensee's submittal of a schedule and method of pressure isolation verification in the RHR system and implementation into the testing program. This item concerns the RHR pump suction pressure isolation valves MOV-RH-700 and 70 The licensee has chosen the pressure monitoring technique described in the initial SER of June 29, 1982. One of these gate valves will be tested each refueling outage to assure that the valves adequately maintain redundant pressure isolation and system integrity. This test procedure and acceptance criteria will be developed and in place before the fifth refueling outage. This item remains open pending incorporation of MOV-RH-700 and 701 testing into the test program, and veri-

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fication that test results are acceptable.

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(0 pen) Inspector Follow Item (85-17-08): Incorporate special operating order for return of 4KV or 480 volt breakers to operation in OM procedures. OM Chapter 36, 4KV Station Service System, Figures and Tables, has been updated via Figure 36-24, Breaker Racking Methodology, to provide appropriate guidance

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for both 4KV and 480 Volt linestarters. The inspector noted that OM Chapter

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1.37, 480 Volt Station Service System, has yet to be updated. This item remains ope (0 pen) Violation (85-22-04): Failure to issue contractor radiation worker termination report. The licensee responded to this violation by letter dated December 16, 1985. This letter noted that past termination report problems

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were apparently limited to craf t personnel and that actions taken at that time were successful in preventing a recurrence. The recent violation was deter-i mined to be due to miscommunication to the 00simetry Lab regarding contractor l personnel (a consultant and a security guard) which had been communicated in a different manner. The licensee committed to issuing a nuclear group direc-

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tive to establish a uniform method of reporting radiation workers who termi-

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i, nate employment at BVP Security personnel are now required to directly i forward a Site Employee Status Report to the Dosimetry Laboratory on a routine

basis. This item remains open pending review of the directive and security

administrative controls over the Site Employee Status Report (0 pen) Violation (85-22-01)

Unauthorized operation of Unit 1/2 boundary isolation valves resulting in an unplanned release of radioactive liquid from

.l BR-TK-7. The licensee responded to this violation by letter dated December 16, 1985. The immediate corrective action steps specified have been pre-viously reviewed in NRC Inspection Reports 85-22 and 85-24. These actions were found to be satisfactor To prevent further recurrence, the licensee a reposted a clearance on all Unit 1 isolation and drain valves on cross-connect j

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lines to Unit 2 and chain locked all potential effluent path valves closed except ball valve For ball valves, the licensee intends to install a

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specially designed clamping device by January 31, 198 The inspectors veri-l fled that the licensee has installed an additional dam at the east end of the south trench to prevent water leakage into Unit 2. Local postings were re-l viewed and found to be satisfactory. Additionally, Unit 1 operating flow schematics and Unit 1/2 interconnection drawings were reviewed for identifi-

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cation of potentially radioactive piping interconnections. All valves were i verified closed and tagged. This item remains open pending verification that

the installation of the clamping devices is completed by January 31, 198 . Plant Operations

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Inspection teurs of the plant areas listed below were conducted during both day and night shifts with respect to Technical Specification (TS)

I compliance, housekeeping and cleanliness, fire protection, radiation I control, physical security and plant protection, operational and main-

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tenance administrative control Control Room

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Primary Auxiliary Building *

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Turbine Building

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Service Building

-- Main Intake Structure

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Main Steam Valve Room

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Purge Duct Room

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East / West Cable Vaults

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Emergency Diesel Generator Rooms

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Containment Building

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Penetration Areas i -- Safeguards Areas

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Various Switchgear Rooms / Cable Spreading Room

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Protected Areas Acceptance criteria for the above areas included the following:

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BVPS FSAR

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-- Technical Specifications (TS)

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BVPS Operating Manual (OM), Chapter 48, Conduct of Operations

-- OM 1.48.5, Section D, Jumpers and Lifted Leads

-- OM 1.48.6, Clearance Procedures

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OM 1.48.8, Records

-- OM 1.48.9, Rules of Practice

-- OM Chapter 55A, Periodic Checks, Operating Surveillance Tests

-- BVPS Maintenance Manual (MM), Chapter 1, Conduct of Maintenance

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BVPS Radcon Manual (RCM)

-- 10CFR50.54(k), Control Room Manning Requirements

-- BVPS Site / Station Administrative Procedures (SAP)

-- BVPS Physical Security Plan (PSP)

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Inspector Judgement Operations The inspector toured tha Control Room regularly to verify compliance with NRC requirements and f acility technical specifications (TS). Direct observations of instrumentation, recorder traces and control panels were made for items important to safety. Included in the reviews were the rod position indicators, nuclear instrumentation systems, radiation moni-tors, containment pressure and temperature parameters, onsite/offsite emergency power sources, availability of reactor protection systems and proper alignment of engineered safety feature systems. Where an abnormal condition existed (such as out-of-service equipment), adherence to ap-propriate TS action statements was independently verified. Also, various operation logs and records, including completed surveillance tests, equipment clearance permits in progress, status board maintenance and temporary operating procedures were reviewed on a sampling basis for compliance with technical specifications and those administrative con-trols listed in paragraph 4 During the course of the inspection, discussions were conducted with operators concerning reasons for selected annunciators and knowledge of recent changes to procedures, facility configuration and plant condition The inspector verified adherence to approved procedures for ongoing ac-tivities observed. Shift turnovers were witnessed and staffing require-ments confirme Except where noted below, inspector comments or ques-tions resulting from these daily reviews were acceptably resolved by licensee personne . During a tour of the Primary Auxiliary Building on December 5, 1985, the inspector noted that containment air lock door control panel was energized. Followup determined that OST 1.47.1, Containment Air Lock Door (s) Type B Leak Test, had been completed at about 4:00 a.m. that morning. The OST only requires the operator to notify the shift supervisor upon completion. It does not require de-ener-gization of the control panels (power switches are located in the control room). The inspector reviewed Station Administrative Pro-cedure 28, Reactor Containment Entry, and OM Chapter 1.47.4A, Reac-i

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tor Containment Access Control. Neither requires the air lock door to be de-energized when not in use. Technical Specification 6.1 requires high radiation areas where the intensity can be greater than 1,000 mrem / hour, to have locked doors to prevent unauthorized entry. The keys are required to be kept under the administrative control of the operations shift supervisor or a facility health physics supervisor. Though the various high radiation areas inside containment are under such controls, the licensee's program for total control over containment entries could be improved. Discus-sions with the operations supervisor indicated that appropriate procedure revisions would be made to require verification that the air lock door is de-energized when not in use. Review of this ac-tion is Unresolved Item (85-27-01).

2. The licensee declared the Beaver County, Pennsylvania, Offsite Emergency Notification System (ENS) inoperable at 12:40 a.m., on December 8, 1985, after the system failed a once per 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> test code check. The NRC Operations Center was notified of the condition within one hour. The problem was traced to the master code genera-tor at the Beaver County Emergency Center transmission tower. The ENS was returned to service at 3:30 a.m. that morning after the problem disappeared during troubleshooting. The ENS again failed a test code check the next day. After technicians removed several electrical cards and cleaned contacts, no further problems were encountered. The inspector noted that the licensee entered this event into their Unit Off Normal reporting system to build a his-torical fil The Columbiana County, Ohio, ENS was declared out-of service at 11:00 a.m. , on December 31, 1985, after failing a radio test chec The licensee made appropriate notifications. Subsequent investiga-tion determined that the radio used to signal the individual sirens would still have been able to properly functio Licensee actions were satisfactor . During a review of the control room logs on December 26, 1985, the inspector noted two instances where operations personnel identified safety-related instrumentation with out-of-date calibration sticker Charging pump 1A discharge pressure indicator CH-PI-151 was found due by December 22, 1985, while returning the pump to service fol-lowing maintenance work on the lube oil system. Since the other two pumps were operable, restoration was delayed one day for I&C to complete calibration. Performance of OST 1.13.10A, Chemical Addition System Valve Position and Pump Operability Check - Train A, was also delayed because the flow indicator on the recirculation line to the chemical additional tank (FI-QS-107) was out of cali-bration. In each case, these were local indicators used during performance of a monthly surveillance test. Discussions with I&C personnel indicated that each calibration had been properly sched-

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uled, but were delayed due to manpower constraints during this time of the yea The inspector toured the control room and verified that safety-related instrumentation had current calibration sticker Since all remote instruments used during surveillance testing (OST, MSP, BVT) are referenced in the specific test, with calibration due dates, the inspector had no further concern c. Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in the areas listed in paragraph 4a above with regard to the following:

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Protected area barriers were not degraded;

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Isolation zones were clear;

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Persons and packages were checked prior to allowing entry into the Protected Area;

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Vehicles were properly searched and vehicle access to the Protected Area was in accordance with approved procedures;

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Security access controls to Vital Areas were being maintained and that persons in Vital Areas were properly authorized;

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Security posts were adequately staffed and equipped, security per-sonnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and

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Adequate lighting was maintaine The inspector discussed site access authorization procedures for con-tractor personnel with the Director of Security to determine whether adequate hckground checks are performe The inspector was informed that DLC audits the background checks of the contractor guard force, and incorporetes background check requirements into their contract with Stone and Webster Engineering Corporation (the A-E and prime contractor).

However, no audits have been performed by DLC on the background checks of these individuals. Followup to determine how the licensee ensures that the required background checks were performed for all personnel granted unescorted site access, is Unresolved Item (85-27-02).

d. Radiation Controls l Radiation controls, including posting of radiation areas, the conditions of step-off pads, disposal of protective clothing, completion of Radi-ation Work Permits, compliance with the conditions of the Radiation Work Permits, personnel monitoring devices being worn, cleanliness of work

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areas, radiation control job coverage, area monitor operability (portable and permanent), area monitor calibration and personnel frisking proce-dures were observed on a sampling basi Plant Housekeeping and Fire Protection Plant housekeeping conditions including general cleanliness conditions and control of material to prevent fire hazards were observed in areas listed in paragraph 4a. Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observe . Engineered Safety Features (ESF) Verification The operability of the Containment Depressurization System was verified during December 1985, by performing walkdowns of accessible portions that included the following as appropriate:

(1) System lineup procedures matched plant drawings and the as-built con-figuratio (2) Equipment conditions were observed for items which might degrade perfor-manc Hangers and supports were operabl (3) The interior of breakers, electrical and instrumentation cabinets were inspected for debris, loose material, jumpers, et (4) Instrumentation was properly valved in and functioning; and had current calibration date (5) Valves were verified to be in the proper position with power availabl Valve locking mechanisms were checked, where require No deficiencies were identifie . Surveillance Activities To ascertain that surveillance of safety-related systems or components is being conducted in accordance with license requirements, the inspector ob-served portions of selected tests to verify that: The surveillance test procedure conforms to technical specification re-quirements.

' Required administrative tpprovals and tagouts are obtained before initi-ating the tes Testing is being accomplished by qualified personnel in accordance with an approved test procedur . .- .- . ._, . _ - - - - - - .

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9 Required test instrumentation is calibrated, i LCOs are met.

i The test data are accurate and complete. Selected test result data was independently reviewed to verify accurac Independently verify the system was properly returned to servic Test results meet technical specification requirements and test discre-

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pancies are rectified.

l The surveillance test was completed at the required frequenc The following in progress tests were witnessed by the inspector:

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MSP 6.39, T-RC422 Delta T-T average Protection Instrument Channel II Calibration, December 4, 198 MSP 2.06, Power Range Neutron Flux Channel NI-42, Quarterly Calibration,

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December 16, 198 OST 1.24.4, Steam Turbine Driven Auxiliary Feedwater Pump Test, December 24, 198 : --

MSP 24.31, F-FW 496 Feedwater Flow Protection Instrumentation Channel i

IV Calibration, December 30, 198 :

No deficiencies were observe . Reactor Plant Component Cooling Water System (CCR) Maintenance Activities Maintenance activities associated with the B pump motor inboard bearing re-placement and A heat exchanger tube cleaning were periodically observed by

the inspector. Equipment control procedures were followed by station per-sonnel and two CCR subsystems remained operable at all times per TS 3.7. '

requirement The B CCR pump was declared inoperable on November 1,1985, af ter lube oil l temperatures reached 205 F for the motor inside bearing. During the month of Dece.nber,1985, several attempts to identify and correct the root cause were unsuccessful as the lube oil temperature would quickly increase without showing signs of leveling off while running the motor uncoupled. Discussions

, with cognizant personnel indicated that the vendor had been contacted for support. High CCR pump and motor bearing temperatures have been a recurring problem at Beaver Valley since about 1980. Further review to identify the root cause of the apparent motor misalignment is Unresolved Item (85-27-03).

Asiatic clam shells (see IE Bulletin: 81-03), some vegetable matter and dead river shad were found in the A and C heat exchangers (CCR E) during November and December, 1985. The maximum accumulation on the tube sheet (river water

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side) amounted to about 15 gallons of shells in CCR-E-C, which appeared to i

be the one most susceptible. Periodic checks have also found a small amount on the river water strainers to the charging pump lube oil cooler Other safety-related heat exchangers, such as the emergency diesel generators, have shown no discernible increase in the differential pressure across the Discussions with station management indicate that the fully grown shells are thought to have been transported by the river water pumps from the pump bays, as opposed to growing in the heat exchangers. The combination of growth in an inactive bay, and transport by revolving screens into the pump bays during the recent high river water conditions, are thought to be the major sourc In addition to the routine heat exchanger performance checks, the licensee has sent divers into the pump bays to remove the silt and shells, and plans l to dredge in front of the intake structure during the next refueling outage (May, 1986). These actions appear acceptable and the inspector had no further question . Reactor Protection System Items Over Temperature - delta T Surveillance Testing The inspector noted through a control room log review that difficulties were encountered during performance of MSP 6.20, Delta T - T Average Protection Instrumentation Channel I Test, Revision 15, on December 2, 1985. Initial discussions with I&C personnel indicated the monthly sur-veillance test found that electrical noise had caused the loop setpoints to change by about 50 mvdc. Troubleshooting found that the noise could be eliminated by placing the lead-lag module (TM-RC-412E) time bias switch in the "out" position, without effecting the validity of the tes Consequently, Field Revision 85-I-51 was approved for MSP 6.2 l The inspector discussed the Channel I noise phanomenon with the I&C supervisor and questioned why the field revision would not also be ap-

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plicable to instrument channels 2 and 3. The inspector was informed that i an incident report would be initiated to review this item. The licensee '

subsequently determined that the revision would be applicable to the i other loop Discussions with I&C engineers revealed that the station had always found i the 30 second lead setpoint (TS Table 2.2.1) at about 28 seconds, the lower end of the plus or minus 10% acceptance band (ebtained from tech manual). Licensee discussions with Westinghouse, supplier of the 7100 i Series Process Instrument System, identified a long standing deficiency

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in station procedures. Apparently, the 18 month calibration procedures

(MSP 6.38 6.39, 6.40) were written to use only the lead-lag switches I

(2.8 .4) of the modules. This, when multiplied by 10, would bring the i lead-lag gei r4- ts to 28 and 4.0 seconds, which was within the plus or minus 10% - . aentation accuracy. To bring the lead setpoint to ex-

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actly 30 4

.onds, it is necessary to place the time bias switch in the

TM-RC 412t module to off. Consequently, the 18 month MSPs were revised to require this on September 17, 198 ,

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During the month of September, 1985, the licensee experienced numerous over Temperature - delta T turbine runback alarm spikes, as discussed '

in detail 5 of NRC Inspection Report 334/85-20. As a result of this problem, DCP 695, Lag Compensation for RCS Delta T and T-average Summa-tors, was performed in October, 1985, to wire two existing summator lag resistors into the circuit as required by the newer model Rosemount RTD When MSP 6.40 was run for post-modification testing, the licensee found that the lead time constant did not meet the acceptance criteria. In-vestigation found the time - bias circuit was not wired into the modul This was subsequently corrected and the test acceptance criteria me Tests on the other two loops were then successfully completed, but the 4 lead time constants for one was found at the lower end of its acceptance band.

The Loop 1 lead setpoint received further investigation during perfor-i' mance of the next monthly test (MSP 6.21), and the time bics switch was

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also found not wired in. These time-bias deficiencies existed since the 7100 series racks were installed and tested in about 1974. The first draft MSPs were prepared by Westinghouse prior to initial plant startu Licensee corrective action is satisfactor b. Negative Flux Rate Trip Setpoints The power range negative rate trip is provided to ensure that DNBR is maintained above 1.30 for a control rod drop accident. At high power

! levels, a single or multiple rod drop accident coupled with the automatic l rod control system maintaining nuclear power equivalent to : rbine power, i could cause an unconservative local DNBR to exist. WCAP-10297, Dropped j Rod Methodology for Negative Flux Rate Trip Plants, provides a generic

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! verification that the DNB design basis is met for those instances of ,

dropped rod (s) which do not result in a reactor trip due to the negative flux rate signal. For any case where the negative flux rate trip is j activated, no DNB analysis is required because there is no return to

power (the reactor trips, terminating the transient). Consequently, a limiting safety system setting of less than or equal to 5% of rated '

thermal power with a time constant of greater than or equal to .

seconds is established by TS Table 2.2- i

) Westinghouse Technical Bulletin NSID-TB-85-13, dated May 28, 1985, noted that some plants have used an incorrect value to align their nuclear in-

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strumentation system power range positive and negative rate trip bis-tables. The incorrect value resulted from a misinterpretation of that specified in the Plant Precautions, Limitations, and Setpoint document i and the nuclear instrumentation system's technical manual alignment pro-

! cedure. This is a concern because the flux rate trip setpoint is used

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in determining the maximum u @ tected dropped rod worth which must be j considered in the DNB analysis. It was recommended that plants review i their test procedure methodology to achieve the proper calibration for j a 5% trip setpoin i i

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The licensee's initial review of the technical bulletin resulted in a request for clarification of the recommended action dated July 25, 198 No action was taken to revise the test procedure used to set the negative rate trip setpoint. Apparently, the licensee was unable to satisfy themselves through several communications with Westinghouse, that the recommended action was correct until December 9, 1985. At that time, it was decided to modify the plant maintenance surveillance procedures to the technical bulletin's recommendation. It was noted that the limiting safety system setpoint in Table 2.2-1 was correct as is cur-rently specified. The positive and negative rate trip setpoints on power range monitor NI-43 were reset on December 11, 1985. The remaining power range monitors were not reset until December 16, 1985, due to manpower availability, and to allow for a burn in time to build up a confidence level that spurious trips would not occu The inspector reviewed the procedure revisions and discussed them with the I&C engineer. The trip signal is induced by making an equivalent voltage step change of 105% to 100% on the lower PRM detector. The !

reactor protection system develops this pulse as a non-linear voltage signal with respect to time. Since it only develops about 66% of its final voltage at the end of 2.0 seconds, the licensee had selected this as the trip setpoin Westinghouse instrumentation personnel apparently determined that this setpoint methodology was non-conservative with re- j spect to instrument loop inaccuracies. Consequently, the MSPs were re- -

vised to account for those inaccuracies by setting the 2.0 second voltage level at 50%. The station is currently drafting a Licensee Event Report for this ite FSAR Section 14.1.3. Rod Cluster Cor. trol Assembly Misalignment, discusses I dropped full length assemblies and takes credit for the power range nega-tive rate tri However, the rod control system has been operated in the manual mode for the past two fuel cycles. The immediate concerns of possibly exceeding limits during a rod drop accident with the RCS in 1 automatic have not been applicable at BVPS-1. However, final resolution did appear to be slow. The Manager of Technical Services acknowledged that concern. The inspector had no further questions at this tim . Cold Weather Preparation The inspector reviewed the Cold Weather Log (0M Chapter 1.54.3) to ensure that the licensee is maintaining effective implementation of protective measures for extreme cold weather in compliance with the November 1, 1979, response to IE Bulletin 79-24. IEB 79-24 requires the licensee to provide adequate protection for safety related process, instrument, and sampling lines to pre-vent freezing during extremely cold weather. In the response letter, the

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licensee stated that the Cold Weather Log lists all piping and equipment that '

requires such protection. The letter also states that the log is completed in October and the plant is winterized by either actuating heat tracing,

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I placing localized heaters, or enclosing or covering areas normally exposed l to the outside environment. During this inspection period, the licensee has ,

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experienced various equipment difficulties as a result of inadequate cold weather protection. Typical examples are the discovery of de-energized heat trace circuits, piping with insulation removed, and frozen instrument line The licensee has stated that they will revise the Cold Weather Log to better meet the requirements of IEB 79-24. Review of the revision and implementation of the log is Unresolved Item (85-27-04).

During subsequent review of heat tracing annunciator panels, the inspector identified that the drawings of annunciator panels in OM Chapter 45, Table 45-3 did not correctly represent the actual plant configuration. Specifically, the actual arrangement of alarms on panel ANN-QS-01 differed from the drawing for 17 of 18 alarms. Verification that the heat tracing panels alarm light i bulb covers are in the correct configuration and update of the OM Chapter tables are Inspector Follow Item (85-27-05).

1 Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was further discussed with the licensee at the conclusion of the report perio _ _ - _ _ - _ . _ - _ _ _ __ - _ _ _ _ _ . _ _ _ _ _ _ _ __ _ _ _ _ . _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . - _ - _ _ _ _ _ _ _ _ _ _ - _ . _ _ _ _ __